U.S. patent application number 14/615632 was filed with the patent office on 2015-08-27 for reservoir and completion quality assessment in unconventional (shale gas) wells without logs or core.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Ridvan Akkurt, Andrew E. Pomerantz, Romain Charles Andre Prioul.
Application Number | 20150240633 14/615632 |
Document ID | / |
Family ID | 49324077 |
Filed Date | 2015-08-27 |
United States Patent
Application |
20150240633 |
Kind Code |
A1 |
Akkurt; Ridvan ; et
al. |
August 27, 2015 |
Reservoir and Completion Quality Assessment in Unconventional
(Shale Gas) Wells Without Logs or Core
Abstract
Embodiments herein relate to a method for recovering
hydrocarbons from a formation including collecting and analyzing a
formation sample, drilling operation data, and wellbore pressure
measurement, estimating a reservoir and completion quality, and
performing an oil field service in a region of the formation
comprising the quality. In some embodiments, the formation sample
is a solid collected from the drilling operation or includes
cuttings or a core sample.
Inventors: |
Akkurt; Ridvan; (Lexington,
MA) ; Prioul; Romain Charles Andre; (Somerville,
MA) ; Pomerantz; Andrew E.; (Lexington, MA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar land |
TX |
US |
|
|
Family ID: |
49324077 |
Appl. No.: |
14/615632 |
Filed: |
February 6, 2015 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
13447109 |
Apr 13, 2012 |
8967249 |
|
|
14615632 |
|
|
|
|
Current U.S.
Class: |
175/50 ;
73/152.03; 73/152.04 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 21/066 20130101; E21B 49/088 20130101; E21B 49/005
20130101 |
International
Class: |
E21B 49/00 20060101
E21B049/00; E21B 43/26 20060101 E21B043/26 |
Claims
1. A method for analyzing a subterranean formation, the method
comprising: obtaining cuttings generated from drilling a wellbore
that traverses the subterranean formation; performing a plurality
of analyses on the cuttings, wherein the plurality of analyses
comprises at least two of: (i) determining at least one of
mineralogy, kerogen content, and kerogen maturity for the cuttings;
(ii) determining at least one of surface area and volume of pores
within the cuttings; (iii) determining porosity of the cuttings;
and (iv) determining elastic properties for the cuttings; and
determining at least one of reservoir quality and completion
quality using data obtained from at least two of the analyses.
2. The method of claim 1, further comprising: obtaining a
logging-while-drilling (LWD) log for the wellbore; determining a
property of the cuttings; and calibrating the cuttings for depth
using the LWD log and the property of the cuttings.
3. The method of claim 2, wherein the LWD log is a gamma radiation
log and the property of the cuttings is gamma radiation.
4. The method of claim 1, further comprising: obtaining a mud log
for the wellbore; determining gas properties for gases within the
mud log; and determining at least one of reservoir quality and
completion quality using (i) the gas properties and (ii) the data
obtained from at least one of the analyses.
5. The method of claim 4, wherein the mud log is obtained by
extracting hydrocarbon gases from drilling fluid used in the
drilling of the wellbore.
6. The method of claim 5, wherein the gas properties comprise gas
type, gas volume, and isotope distribution.
7. The method of claim 1, further comprising: designing an oil
field service for the subterranean formation using at least one of
the reservoir quality and the completion quality.
8. The method of claim 7, further comprising: performing the oil
field service on the subterranean formation.
9. The method of claim 7, wherein the oil field service is a
completion service.
10. The method of claim 8, wherein the completion service is a
hydraulic fracturing service.
11. The method of claim 1, wherein determining at least one of
mineralogy, kerogen content, and kerogen maturity for the cuttings
comprises performing at least one of a X-Ray Fluorescence
measurement, a X-Ray Diffraction measurement, and a Fourier
Transform Infrared Spectroscopy measurement.
12. The method of claim 11, wherein determining at least one of
mineralogy, kerogen content, and kerogen maturity for the cuttings
comprises performing at least two of a X-Ray Fluorescence
measurement, a X-Ray Diffraction measurement, and a Fourier
Transform Infrared Spectroscopy measurement.
13. The method of claim 1, wherein determining mineralogy, kerogen
content, and kerogen maturity for the cuttings comprises performing
a diffuse reflectance infrared fourier transform spectroscopy
measurement on the cuttings.
14. The method of claim 1, wherein determining porosity of the
cuttings comprises performing nuclear magnetic resonance
measurements on the cuttings.
15. The method of claim 1, wherein determining at least one of
surface area and volume of pores within the cuttings comprises
measuring gas sorption.
16. The method of claim 1, wherein determining elastic properties
for the cuttings comprises performing ultrasonic measurements on
the cuttings.
17. The method of claim 1, wherein determining elastic properties
for the cuttings comprises using a rock physics model, the
mineralogy for the cuttings, and the porosity of the cuttings to
compute elastic moduli for the cuttings.
18. The method of claim 1, wherein the analysis of the subterranean
formation is performed without using data obtained from well
logs.
19. The method of claim 1, wherein the analysis of the subterranean
formation is performed without using data obtained from wireline
well logs.
20. The method of claim 1, wherein the analysis of the subterranean
formation is performed without using data obtained from cores.
21. A method for analyzing a subterranean formation, the method
comprising: (i) obtaining cuttings generated from drilling a
wellbore that traverses the subterranean formation; (ii)
determining at least one of mineralogy, kerogen content, and
kerogen maturity for the cuttings; (iii) determining at least one
of surface area and volume of pores within the cuttings; (iv)
determining porosity of the cuttings; and (v) determining at least
one of reservoir quality and completion quality using data obtained
from processes (ii), (iii), and (iv).
22. The method of claim 21, further comprising: (vi) determining
elastic properties for the cuttings; and wherein determining at
least one of reservoir quality and completion quality comprises
using data obtained from processes (ii), (iii), (iv), and (vi).
23. The method of claim 21, further comprising: designing an oil
field service for the subterranean formation using at least one of
the reservoir quality and the completion quality.
24. A method for analyzing a subterranean formation, the method
comprising: (i) obtaining cuttings generated from drilling a
wellbore that traverses the subterranean formation; (ii)
determining at least one of mineralogy, kerogen content, and
kerogen maturity for the cuttings; (iii) determining at least one
of surface area and volume of pores within the cuttings; (iv)
determining porosity of the cuttings; and (v) determining at least
one of reservoir quality and completion quality using data obtained
from processes (ii), (iii), and (iv) and without using data
obtained from wireline well logs; (vi) designing an oil field
service for the subterranean formation using at least one of the
reservoir quality and the completion quality; and (vii) performing
the oil field service on the subterranean formation.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This is a continuation application of co-pending U.S. patent
application Ser. No. 13/447,109 to Ridvan Akkurt, et al. filed on
Apr. 13, 2012, and entitled "Reservoir and Completion Quality
Assessment in Unconventional (Shale Gas) Wells Without Logs or
Core," which is hereby incorporated in its entirety for all intents
and purposes by this reference.
FIELD
[0002] This application relates to methods and apparatus to provide
information for the recovery of hydrocarbons. Specifically,
embodiments described herein collect information and manipulate it
to efficiently stage a well services operation without reliance on
wireline tools or logging while drilling activities.
BACKGROUND
[0003] Often, an oil field service will be selected and tailored in
response to information collected by logging while drilling and/or
by exposing a region of a wellbore to a wireline tool. These
methods require equipment that is delicate and expensive and
methods that require human and computational resources that are
burdensome, especially in remote locations or with wells that may
generate smaller returns on investment. In formations that are in
remote locations or that do not have recovery plans with the
economic resources for these tools, low-cost, local, low technology
methods are selected to roughly estimate the reservoir
properties.
[0004] Some oil field services may require geomechanical properties
of a formation for a variety of reasons without the use of a
logging while drilling tool or wireline tool. There may be a need
to complement tool failure. A wellbore may be drilled without core
data or log information. A drilling regime may include multiple
lateral wells from one initial wellbore and the costs for core
and/or log data may be unreasonably burdensome. Some embodiments
may use a drill string with no tools for logging. Some embodiments
may be performed on site in near real time without time for data
actualization, that is, the drill string may remain in the wellbore
as people timely use the information available to them without
remote mathematical analysis and without operating time lag. Some
embodiments may manipulate the data in time to guide the completion
time. Also, some of the techniques to address these issues, such as
laboratory measurements and some logs, require post-analysis, and
interpretation of the data that cannot be done within the drilling
timeframe.
[0005] Further, while some vertical pilot wells are logged and
evaluated in an unconventional play, stimulated horizontal wells
are rarely logged or cored. The cost of acquiring the information
and/or the associated rig time needed during acquisition (which
means that the rig cannot be used for drilling or stimulation
elsewhere) are two main reasons for this trend. On the other hand,
most of the production from a horizontal well comes from a small
portion of the completed section. A typical number is 70/30,
implying that 70 percent of the production comes from 30 percent of
the horizontal well. More efficient use of funds and resources is
warranted. Change can only take place with better understanding of
the reservoir and completion quality of the formations which
require petrophysical and geomechanical data. The solution must be
low cost and efficient in terms of delivery times (real or near
real-time). It must not introduce any inefficiency into the
development program (such as extended rig time for data
acquisition) and must be based on a simple workflow that can be
carried at the wellsite by non-experts.
[0006] Also, the hydraulic fracturing stimulation of unconventional
organic shale reservoirs is performed today in mostly horizontal
wells where heterogeneities of petrophysical and mechanical
properties along the well are known to be very significant. Staging
requires the identification of sections of the well with both good
reservoir quality and good completion quality. Completion quality
estimates rely on changes in elastic, rock strength, and stress
properties along the well reflect variations (heterogeneity) of
mechanical properties along the well.
SUMMARY
[0007] Embodiments herein relate to a method for recovering
hydrocarbons from a formation including collecting and analyzing a
formation sample, estimating a reservoir and completion quality,
and performing an oil field service in a region of the formation
comprising the quality. Embodiments herein relate to a method for
recovering hydrocarbons from a formation including collecting and
analyzing a formation sample and a gas record, estimating a
reservoir and completion quality, and performing an oil field
service in a region of the formation comprising the quality.
Embodiments herein relate to a method for recovering hydrocarbons
from a formation including collecting and analyzing a formation
sample, drilling operation data, and wellbore pressure measurement,
estimating a reservoir and completion quality, and performing an
oil field service in a region of the formation comprising the
quality.
[0008] Embodiments herein relate to a method for recovering
hydrocarbons from a formation including collecting and analyzing
drilling operation data and wellbore pressure measurement,
estimating a reservoir and completion quality, and performing an
oil field service in a region of the formation comprising the
quality. Embodiments herein relate to a method for recovering
hydrocarbons from a formation including collecting and analyzing a
formation sample, drilling operation data, gas record, and wellbore
pressure measurement, estimating a reservoir and completion
quality, and performing an oil field service in a region of the
formation comprising the quality. Embodiments herein relate to a
method for recovering hydrocarbons from a formation including
collecting and analyzing a gas record, estimating a reservoir and
completion quality, and performing an oil field service in a region
of the formation comprising the quality. Embodiments herein relate
to a method for recovering hydrocarbons from a formation including
collecting and analyzing drilling operation data, estimating a
reservoir and completion quality, and performing an oil field
service in a region of the formation comprising the quality.
Embodiments herein relate to a method for recovering hydrocarbons
from a formation including collecting and analyzing a formation
sample, drilling operation data, and/or wellbore pressure
measurement, estimating a reservoir and completion quality, and
performing an oil field service in a region of the formation
comprising the quality. In some embodiments, the formation sample
is a solid collected from the drilling operation or includes
cuttings or a core sample.
FIGURES
[0009] FIG. 1 is a flow chart illustrating components of an
integrated process for combining information from a variety of
sources.
[0010] FIG. 2 is a flow chart illustrating components of depth
calibration of cuttings using gamma ray information.
[0011] FIG. 3 is a flow chart illustrating components of
mineralogy, kerogen content, and maturity analysis.
[0012] FIG. 4 is a flow chart illustrating components of
mineralogy, kerogen content, and maturity analysis.
[0013] FIG. 5 is a flow chart illustrating components of gas
sorption analysis for surface area and pore volume.
[0014] FIG. 6 is a flow chart illustrating components of porosity
analysis.
[0015] FIG. 7 is a flow chart illustrating components of elastic
property analysis.
[0016] FIG. 8 is a flow chart illustrating components for intrinsic
specific energy and rock strength analysis.
[0017] FIG. 9 is a flow chart illustrating closure stress
analysis.
DESCRIPTION
[0018] At the outset, it should be noted that in the development of
any such actual embodiment, numerous implementation-specific
decisions must be made to achieve the developer's specific goals,
such as compliance with system related and business related
constraints, which will vary from one implementation to another.
Moreover, it will be appreciated that such a development effort
might be complex and time consuming but would nevertheless be a
routine undertaking for those of ordinary skill in the art having
the benefit of this disclosure. In addition, the composition
used/disclosed herein can also comprise some components other than
those cited. In the summary of the invention and this detailed
description, each numerical value should be read once as modified
by the term "about" (unless already expressly so modified), and
then read again as not so modified unless otherwise indicated in
context. Also, in the summary of the invention and this detailed
description, it should be understood that a concentration range
listed or described as being useful, suitable, or the like, is
intended that any and every concentration within the range,
including the end points, is to be considered as having been
stated. For example, "a range of from 1 to 10" is to be read as
indicating each and every possible number along the continuum
between about 1 and about 10. Thus, even if specific data points
within the range, or even no data points within the range, are
explicitly identified or refer to only a few specific, it is to be
understood that inventors appreciate and understand that any and
all data points within the range are to be considered to have been
specified, and that inventors possessed knowledge of the entire
range and all points within the range.
[0019] The statements made herein merely provide information
related to the present disclosure and may not constitute prior art,
and may describe some embodiments illustrating the invention.
DEFINITIONS
[0020] The reservoir quality (hereafter RQ) is defined by a number
of petrophysical and hydrocarbon properties (e.g., porosity,
permeability, total organic content versus total inorganic content
and maturation, hydrocarbon content and type, gas sorption
mechanisms) defining reservoir potential.
[0021] The completion quality (CQ) depends on the poromechanical
properties of the field and reservoir, which means the conditions
that are favorable to the creation, propagation and containment of
hydraulic fractures, as well as the placement of proppant and
retention of fracture conductivity. It depends mainly on the
intrinsic geomechanics properties, i.e., in situ stress field, pore
pressure, material properties (elastic, yield or quasi-brittle
failure, hardness, rock-fluid sensitivity), their anisotropic
nature and their spatial heterogeneities, as well as the presence
of discontinuities (such as natural fractures or geological
layering) and the orientation of the well. SPE 144326 provides more
information for the definitions of RQ and CQ and is incorporated by
reference herein.
[0022] Elastic properties include the properties of in situ rocks
under either isotropic or anisotropic conditions including Young's
moduli, Poisson ratios and shear moduli in classical solid
mechanics (E and v for isotropic rocks; E.sub.h, E.sub.v, v.sub.h,
v.sub.v, and G.sub.v for transversely anisotropic rocks also
referred as TI rocks).
[0023] Rock strength of in situ rocks under either isotropic or
anisotropic conditions is known as compressive strength UCS,
tensile strength TS and fracture toughness KIC.
[0024] In situ stress field and pore pressure and its spatial
variations within the reservoir include the orientation and
magnitude of the minimum stress (often the minimum horizontal
stress) and are critical to design hydraulic fracturing (this
stress is also referred as the closure stress in hydraulic
fracturing stimulation literature). The other two stress magnitudes
(often the vertical and maximum horizontal stress, if vertical
stress is maximum), as well as the pore pressure are also
important.
[0025] Further, as a well is being drilled, the rock that is
undergoing the drilling is cut or otherwise fragmented into small
pieces, called "cuttings," that are removed from the bulk of the
formation via drilling fluid. The process is similar to drilling a
hole in a piece of wood which results in the wood being cut into
shavings and/or sawdust. Cuttings are representative of the
reservoir rock--although they have been altered by the drilling
process, they still may provide an understanding of the reservoir
rock properties. This is often referred to as "mud logging" or
"cuttings evaluation." For effective logging or evaluation as
described below, the cuttings are prepared by removing residual
drilling fluids.
[0026] Staging is the design of the locations of the multiple
hydraulic fracturing stages and/or perforation clusters, an
interval for which services will be performed on a well. A single
stage, which is individually designed, planned and executed,
comprises one part in a series of work to be done on the well.
Stages are usually defined by a sequential list of numbers and may
include a description of the well depth interval(s) and or services
to be performed. Stages can also relate to the people, equipment,
technical designs or time periods for each interval (typically
related to pressure pumping).
[0027] The term "unconventional" is used refer to a formation where
the source and reservoir are the same, and stimulation is required
to create production.
[0028] The "source" aspect implies that the formation contains
appreciable amounts of organic matter, which through maturation has
generated hydrocarbons (gas or oil, as in Barnett and Eagle Ford,
respectively).
[0029] The "reservoir" aspect signifies that the hydrocarbons have
not been able to escape and are trapped in the same space where
they were generated. Such formations have extremely low
permeabilities, in the order of nanodarcies, which explains why
stimulation in the form of hydraulic fracturing is needed.
[0030] Bitumen and kerogen are the non-mobile, organic parts of
shales. Bitumen is defined as the fraction that is soluble in a
solvent (typically a polar solvent such as chloroform or a
polarizable solvent such as benzene). Kerogen is defined as the
fraction that is insoluble.
[0031] Rock cores are reservoir rocks collected with a special tool
that produces large samples with little exposure to drilling
fluids.
[0032] Wireline (WL) is related to any aspect of logging that
employs an electrical cable to lower tools into the borehole and to
transmit data. Wireline logging is distinct from
measurements-while-drilling (MWD) and mud logging.
[0033] Measurements-while-drilling includes evaluation of physical
properties, usually including pressure, temperature and wellbore
trajectory in three-dimensional space, while extending a wellbore.
MWD is now standard practice in offshore directional wells, where
the tool cost is offset by rig time and wellbore stability
considerations if other tools are used. The measurements are made
downhole, stored in solid-state memory for some time and later
transmitted to the surface. Data transmission methods vary from
company to company, but usually involve digitally encoding data and
transmitting to the surface as pressure pulses in the mud system.
These pressures may be positive, negative or continuous sine waves.
Some MWD tools have the ability to store the measurements for later
retrieval with wireline or when the tool is tripped out of the hole
if the data transmission link fails.
[0034] MWD tools that measure formation parameters (resistivity,
porosity, sonic velocity, gamma ray) are referred to as
logging-while-drilling (LWD) tools. LWD tools use similar data
storage and transmission systems, with some having more solid-state
memory to provide higher resolution logs after the tool is tripped
out than is possible with the relatively low bandwidth, mud-pulse
data transmission system. Embodiments described herein relate to
the field of geomechanics and its application to the oil and gas
industry. Geomechanics is an integrated domain linking in situ
physical measurements of rock mechanical properties via wellbore
logging or wellbore drilling, in situ hydraulic measurements of in
situ pore pressure and stress field, surface laboratory
measurements on cores to engineering practices for drilling,
fracturing and reservoir purposes via the construction of
integrated earth models, and modeling tools and workflows.
Reservoir Quality and Completion Quality
[0035] Formation evaluation in gas shale and oil-bearing shale
reservoirs involves estimation of quantities such as mineralogy,
kerogen content and thermal maturity (reflecting the extent of
alteration of the kerogen due to thermal processes). These
quantities are important for estimating the reservoir quality and
completion quality of the formation, and measurement of these
quantities as a function of depth is desirable in nearly every well
in shale plays. Embodiments herein provide a procedure for
estimating all three of these quantities. This could be performed
simultaneously using Fourier Transform Infrared Spectroscopy FTIR)
as described below. We could also do it not simultaneously using a
combination of X-Ray Fluorescence (XRF), X-Ray Diffraction (XRD),
and Diffuse Reflectance Infrared Fourier Transform Spectroscopy
(DRIFTS) or other methods described below. The procedure involves
the use of infrared spectroscopy, for example infrared spectroscopy
recorded using a Fourier transform technique (FTIR) as is commonly
used for estimating mineralogy in conventional rocks that have been
cleaned of hydrocarbons. These measurements can be performed using
FTIR spectra recorded in diffuse reflection mode, transmission
mode, photoacoustic mode, with a diamond-window compression cell.
Some embodiments may also use XRD, XRF, and/or DRIFTS.
[0036] Embodiments described herein fully exploit the data that may
be collected using cuttings and/or core samples, drilling operation
data, pressure tests, gamma ray feedback, and/or other methods to
estimate reservoir quality and completion quality. The overall goal
is to provide timely, lower cost formation property estimates to
facilitate more efficient drilling, staging for hydraulic
fracturing, perforation cluster position, completions, and/or
general reservoir planning and management. The different methods
employed by embodiments of the invention to estimate elastic
properties, rock strength, and minimum horizontal stress may vary
from wellbore to wellbore and wellbore region to wellbore region.
The overall goal of the process is selective staging. An
intermediate goal is characterization of three geomechanical
properties: elastic properties, rock strength and minimum stress
magnitude to facilitate efficient recovery of hydrocarbons.
Characterization of the mineral (inorganic) and nonmineral
(organic) content of formation samples is the objective including
weight fractions of inorganic and organic content, total organic
content (TOC), and/or mineralogy.
[0037] Generally, embodiments described herein relate to collecting
and analyzing a formation sample, data from a drilling operation,
and data from a wellbore pressure measurement; estimating a
reservoir and completion quality; and performing an oil field
service in a region of the formation comprising the quality. The
reservoir qualities may include a mud gas log, DRIFTS, Gas
Sorption, XRD, XRF, Natural Spectral Gamma Ray (GR), Nuclear
Magnetic Resonance (NMR), drilling data, calcimetry or a
combination thereof. One embodiment offers a reservoir and/or
production engineering solution based on concepts developed from
reservoir geoscience subspecialties of petrophysics, geochemistry
and geomechanics; by providing data on reservoir and completion
quality, which can be used to optimize a stimulation program
(hydraulic fracturing) in the planning stage, or assess the source
of discrepancies among different wells in the post-mortem
phase.
[0038] The integration of several measurements in a seamless and
meaningful way to provide an answer to guide a completion
(stimulation) program, at the well site at or near real-time
conditions, in an efficient way (no additional rig time) and at low
cost is desirable. The sample cleaning and preparation
methodologies developed herein, as well as the extraction of rock
strength properties from drilling data are also described
herein.
[0039] In particular, some embodiments characterize the
geomechanical properties of a formation along a borehole while it
is being drilled. Embodiments may be targeted to lateral wells in
unconventional shale reservoirs where hydraulic fracturing is
performed. The characterization relates to up to three key
properties: (1) elastic properties, (2) rock strength and (3)
minimum stress magnitude. Generally, (1) the characterization is
done without the need for WL or LWD logs, although if present, they
are used as redundant and complementary information (2) the
acquisition and analysis of the data is done as we drill the well
(often not real time but within the timeframe of the drilling
time), and (3) relies on a combination of techniques bundled
together. These techniques rely upon combined information and
combined analysis techniques and material recovery methods.
Combining the information provides more definitive knowledge of a
formation by combining this information to characterize reservoir
quality and completion quality to craft a staging routine with
efficiency and greater volume of hydrocarbon recovery.
Flow Charts
[0040] FIG. 1 is a flow chart illustrating one embodiment of the
methods described herein, components of an integrated process for
combining information from a variety of sources. Additional
embodiments may include additional steps or delete some steps. An
exact order of data collection and manipulation is not implied by
FIG. 1. Some embodiments may benefit from repeating steps and some
embodiments may omit some steps.
Initial Data Collection
Box 101: Acquire Mud Log at Surface
[0041] In this step 101, hydrocarbon gases entrained in the
drilling fluid are extracted and analyzed. The process is repeated
while the well is drilled, producing a log of the gas analysis.
Hydrocarbon gases enter the drilling fluid primarily when the rock
containing them is crushed by the drill bit and possibly also by
flow from the formation to the borehole (depending on the
difference between the formation pore pressure and the wellbore
pressure). Thus, this procedure produces a log of hydrocarbon gas
content and composition over the course of the well.
[0042] The measurement occurs by extracting hydrocarbon gases from
the drilling fluid and then analyzing those gases. Extraction is
performed using an extractor or a degasser such as the FLEX.TM.
fluid extractor commercially available from Schlumberger Technology
Corporation of Sugar Land, Tex. that heats the drilling mud to a
constant temperature and maintains a stable air-to-mud ratio inside
the extraction chamber. Analysis occurs with a gas chromatograph or
a gas chromatograph/mass spectrometer such as the FLAIR.TM. system
which is commercially available from Sugar Land, Tex. Analysis can
also involve isotope measurements which are commercially available
from Schlumberger Technology Corporation of Sugar Land, Tex.
Analysis can also use tandem mass spectrometry as described in U.S.
patent application Ser. No. 13/267,576, entitled, "Fast Mud Gas
Logging using Tandem Mass Spectroscopy," filed Oct. 6, 2011, and
incorporated by reference herein in its entirety. Preferably the
concentration of gases entering the well is subtracted from the
concentration of gases exiting the well to correct for gas
recycling.
Box 102: Acquire LWD GR Log
[0043] This step 102 involves measuring the amount of
naturally-occurring gamma radiation. The measurement provides
information about the chemical composition of the formation, in
particular the uranium, thorium and potassium concentrations. In
LWD, the measurement is commonly run in one of four modes: total
gamma ray (providing a weighted average of the uranium, thorium,
and potassium concentrations), spectral gamma ray (estimating the
individual concentrations of uranium, thorium, and potassium),
azimuthal gamma ray (provides a borehole image of the gamma ray
response), and gamma ray close to the drill bit (places the sensor
relatively close to the drill bit). Each of those modes delivers a
total gamma ray value; some also deliver additional
information.
[0044] This measurement is performed using a scintillation
detector. It can be performed with common MWD tools such as
PATHFINDER.TM., which is commercially available from Schlumberger
Technology Corporation of Sugar Land, Tex.
Box 103: Collect Drilling Cuttings from the Shaker at the
Surface
[0045] This step 103 involves removing the cuttings from the mud,
as is necessary for subsequent analysis of the cuttings. Cuttings
can be removed from the mud using a shale shaker, which is a
vibrating mesh with an opening around 150 microns. Cuttings are
collected from the top of the shaker while mud falls through the
shaker. Additional process steps 103 and 111 are more fully
described in U.S. patent application Ser. No. 13/446,985, Method
and Apparatus to Prepare Drill Cuttings for Petrophysical Analysis
by Infrared Spectroscopy and Gas Sorption, filed Apr. 13, 2012,
which is incorporated by reference herein.
Box 111: Clean Cuttings
[0046] Cuttings collected in step 103 are coated with mud,
including a base fluid (typically either oil or water) and numerous
liquid and solid additives. The mud must be substantially removed
from the cuttings or it will impact the subsequent analyses (steps
132-135). In particular, oil base fluids and organic mud additives
contain organic carbon, which if left on the cuttings will
artificially elevate the kerogen (organic carbon) measurement in
step 132.
[0047] Cuttings from wells drilled with oil based mud can be
cleaned by washing them with a solvent such as the base oil over a
sieve with opening size similar to the shale shaker's. The washing
step can include agitation of the cuttings in solvent, for example
using a rock tumbler. The solvent can be supplemented with a
surfactant such as ethylene glycol monobutyl ether. Subsequent
washing with a volatile solvent such a pentane can be used to
remove residual base oil. Ideally, another washing will be
performed at elevated temperature, elevated pressure and/or reduced
particle size to remove mud more effectively.
Box 121: Depth Calibration of Cuttings Using GR
[0048] In order to interpret cuttings data, the depth interval
represented by cuttings samples must be well known. An initial
estimate of the depth interval is typically obtained from the known
depth of the bit, borehole size and mud circulation rate. However,
this estimate is often insufficient. Additionally, this estimate
does not account for the possibility of cuttings being trapped in
highly deviated sections of the well, contamination from formation
material at other depths caving into the well, etc.
[0049] A more accurate estimate of the cuttings depth can be
obtained by comparing the gamma ray value of cuttings with the
gamma ray value measured in 102. If the two gamma ray values match,
the cuttings are considered representative of the formation at that
depth. The match can occur using the initially estimated cuttings
depth or after applying a small shift to the depth. If no agreement
is found, the cuttings are flagged as not being representative of
the formation.
[0050] The gamma ray value of cuttings can be measured in multiple
ways. As an example, direct gamma ray measurement is described in
Ton Loermans, Farouk Kimour, Charles Bradford, Yacine Meridji,
Karim Bondabou, Pawel Kasprzykowski, Reda Karoum, Mathieu Naigeon,
Alberto Marsala, 2011, Results From Pilot Tests Prove the Potential
of Advanced Mud Logging. SPE/DGS Saudi Arabia Section Technical
Symposium and Exhibition, 15-18 May 2011, Al-Khobar, Saudi Arabia;
Society of Petroleum Engineers 149134, which is incorporated by
reference herein. As another example, the gamma ray value can be
computed from the concentrations of Thorium, Uranium, and
Potassium, using the known equation:
[0051] Gamma ray (API)=4*Th (ppm)+8*U (ppm)+16*K (%). The
concentrations of Th, U and K can be measured using x-ray
fluorescence.
[0052] FIG. 2 provides a flow chart of step 121. Specifically, the
direct gamma ray and/or XRF and estimated GR from K, Th, and U
measurements are used to determine agreement between the direct and
LWD gamma rays. When there is good alignment, the cuttings are
calibrated in depth with a quality factor indicator. If there is
poor agreement, depth shift may be used until there is good
agreement at which time the cutting are considered calibrated in
depth with a quality factor indicator. If no form of depth shifting
results in good agreement, the cuttings may be flagged as not
representative of the formation subsurface. Some embodiments may
benefit from comparing the gamma ray data and formation sample for
depth matching. Some embodiments may benefit from identifying
samples that are not representative of the subsurface. In some
embodiments, the not representative sample identification is used
to assess the quantitative uncertainty in the quality.
Box 104: Acquisition of Drilling Data at the Surface or
Downhole
[0053] This step 104 involves the acquisition of accurate drilling
data using either measurements at the surface on the rig or
downhole in situ measurements. Typically, surface drilling
measurements at the surface on the rig include: (1) top drive or
rotary table angular rotational speed (SRPM), (2) top drive or
rotary table torque to estimate "surface" torque-on-bit (STOB), (3)
Hook load pressure (consisting of string weight minus weight of
displaced mud; the string weight being the kelly assembly or top
drive, drill string, bottom hole assembly and drill bit) to
estimate "surface" weight-on-bit (SWOB), (4) Block position to
estimate "surface" rate-of-penetration (SROP) and depth (hole and
bit).
[0054] Typically, downhole drilling measurements include direct
measurements of at- or near-bit weight-on-bit (WOB), torque-on-bit
(TOB), rate-of-penetration (ROP) and angle rotational speed of the
bit (RPM), for example using Schlumberger's Integrated weight on
bit sub which is commercially available from Schlumberger
Technology Corporation of Sugar Land, Tex.
Box 105: Acquisition of Pressure Versus Time: Mini-Hydraulic Stress
Test (LOT, X-LOT)
[0055] This step 105 involves the acquisition of data to measure in
situ closure stress from mini-hydraulic fracture test. During
drilling, this type of test can be performed either after the
casing and cement is set as a formation integrity test at the
bottom of casings or using an inflatable packer to isolate the
bottom of the wellbore. The formation integrity test requires to
drill out cement and around 10 feet of new formation, whereas the
openhole packer test requires to install a open packer assembly on
a bottom hole assembly. Both require installing measurements
devices downhole and at the surface to record tubing pressure,
annulus pressure and flow rate during pumping. Then,
microfracturing is done by pumping of drilling mud as fracturing
fluid. Details description of the sequence of events to perform
such tests is provided via several references including two SPE
papers A. A. Daneshy, G. L. Slusher, P. T. Chisholm, D. A. Magee
"In Situ Stress Measurements During Drilling" Journal of Petroleum
technology, August 1986, SPE 1322 and K. R. Kunze and R. P.
Steiger, Exxon Production Research Co. 1992 "Accurate In situ
Stress Measurements During Drilling Operations" SPE 24593, both of
these papers are incorporated by reference herein. One adequate
field test procedure is known as extended leakoff test (XLOT). In
order to estimate a closure representative of the formation,
multiple leakoff cycles are conducted, accurate surface and
downhole pressure is measured, after shut-in, pressure decrease is
monitored for a sufficient time (.about.30 minutes), fluid
densities are measured accurately.
Analysis Steps 131-137
Box 131: Measure Gas Properties Including Volume, Type, and Isotope
Distribution
[0056] For the performance of step 131, measuring the gas
properties including volume, type, and isotope distribution, the
analysis of box 101 returns three sets of values. First, the
concentration of gases is measured. The concentration is measured
of each gas in air, but using the flow rates that can be converted
to the concentration of gas in the mud. Second, the composition of
the gas is measured. Gases in the range C1-CS or C1-C8 are commonly
determined, for example, as in Daniel McKinney, Matthew Flannery,
Hani Elshahawi, Artur Stankiewicz, Ed Clarke, Jerome Breviere and
Sachin Sharma, 2007, Advanced Mud Gas Logging in Combination with
Wireline Formation Testing and Geochemical Fingerprinting for an
Improved Understanding of Reservoir Architecture, SPE Annual
Technical Conference and Exhibition, 11-14 Nov. 2007, Anaheim,
Calif., U.S.A, Society of Petroleum Engineers 109861, which is
incorporated by reference herein. Third, the isotopic composition
of the gases is measured. Commonly the .delta..sup.13C value of
CH.sub.4 is determined. Other measurements such as the
.delta..sup.13C value of all of the gases, the .delta..sup.2H
values or clumped isotopes can be determined. These measurements
are repeated while the well is drilled to form a log.
Box 132: Analysis for Mineralogy, Kerogen Content and Maturity
[0057] This step 132 involves measuring the chemical composition of
the cuttings. First, the mineralogy is measured using techniques
such as vibrational spectroscopy (including infrared spectroscopy
in transmission, diffuse reflection or photoacoustic mode as well
as Raman spectroscopy in transmission or reflection mode), x-ray
fluorescence, x-ray diffraction, scanning electron microscopy,
energy dispersive spectroscopy, and wavelength dispersive
spectroscopy. Second, the kerogen content (or total organic
content) is measured using techniques such as vibrational
spectroscopy, acidization followed by combustion, the indirect
method or Rock Eval such as the output from a Rock Eval 6 analyzer
which is commercially available from Vinci Technologies of
Nanterre, France. Third, the maturity is measured using techniques
such as vibrational spectroscopy, Rock Eval, petrography including
vitrinite reflectance such as the service provided by Pearson Coal
Petrography of South Holland, Ill., thermal alteration index, or
elemental analysis. Preferably these quantities are measured
simultaneously. For example, U. S. Patent Provisional Patent
Application Ser. No. 61/523,650, incorporated by reference herein,
describes a method to measure mineralogy and kerogen content
simultaneously using infrared spectroscopy in diffuse reflection
mode. As another example, describes a method to measure mineralogy,
kerogen content and maturity simultaneously using infrared
spectroscopy. U.S. patent application Ser. No. 13/446,975, filed
Apr. 13, 2012 entitled METHODS AND APPARATUS FOR SIMULTANEOUS
ESTIMATION OF QUANTITATIVE MINEROLOGY, KEROGEN CONTENT AND MATURITY
IN GAS SHALE AND OIL-BEARING SHALE provides more details and is
incorporated by reference herein. These measurements are repeated
while the well is drilled to form a log.
[0058] FIG. 3 is a flow chart of one embodiment of analysis for
mineralogy, kerogen content, and maturity with details for one
embodiment of step 132. XRF for elemental concentrations, XRD
mineralogy, DRIFTS for mineralogy and kerogen content, and FTIR for
mineralogy kerogen content, and kerogen maturity may be performed
and combined to provide a log of inorganic mineralogy (weight
fraction) from cuttings. The DRIFTS and FTIR results may be used to
form a log of total organic content (weight fraction) from
cuttings. The FTIR results may be used to form a log of organic
kerogen maturity from cuttings. As the arrows indicate, the
constituent steps may be combined. In some embodiments, the XRF and
XRD data may form one log. These logs may be combined for an
analysis of elastic properties and for reservoir quality
characterization. FIG. 4 provides additional details of how the
processes may work together. In some embodiments, XRF, XRD, DRIFTS
and FTIR may all be performed. In some embodiments only three of
the four may be performed. In some embodiments, only one or two may
be performed. The results of the processes may be performed to form
a log of inorganic mineralogy and/or of TOC.
Box 133: Analysis of Gas Sorption for Surface Area and Pore
Volume
[0059] This step 133 involves measuring the physical structure of
the cuttings. The gas sorption of shale is measured and interpreted
following the method of U.S. patent application Ser. No.
13/359,121, entitled, "Gas Sorption Analysis of Unconventional Rock
Samples," filed Jan. 26, 2012, and incorporated by reference
herein. The procedure involves an instrument such as Micromeritics
ASAP 2420 commercially available Micromeritics of Norcross, Ga. and
interpretation of the data following the procedure of Brunauer, S.;
Emmett, P. H. & Teller, E., Adsorption of Gases in
Multimolecular Layers, Journal of the American Chemical Society,
1938, 60, 309-319. The measurement produces an estimate of surface
area and pore volume. Both quantities generally increase with
increasing kerogen content and maturity, although for highly mature
samples the surface area will begin to decrease with increasing
maturity as pores coalesce. These measurements are repeated while
the well is drilled to form a log.
[0060] FIG. 5 is a flow chart of for an analysis of gas sorption
for surface area and pore volume. The gas sorption measurement may
be used to form a log of surface area and pore volume from cuttings
and then used as a component for reservoir quality
characterization.
Box 134: Analysis for Porosity
[0061] This step 134 involves measuring the porosity of the
cuttings. Porosity can be measured by nuclear magnetic resonance,
as described in SPE 149134. Preferably porosity is measured by
combination of gas sorption and bulk density, where gas sorption is
described in 133 and bulk density is measured using an instrument
such as GeoPyc 1360 from Micromeritics company. These measurements
are repeated while the well is drilled to form a log.
[0062] FIG. 6 is a flow chart of one embodiment of this step 134.
Gas sorption and bulk density measurements may be combined with NMR
lab measurements to form a porosity log for reservoir quality
characterization.
Box 135: Analysis for Elastic Properties
[0063] This step 135 includes the determination of the elastic
properties of the drilling cuttings collected and prepared in step
103-111-121. The elastic properties are determined in two
independent ways: first directly by measuring the ultrasonic
velocities and second indirectly by combining a rock physics model
with the knowledge of the fraction of the different mineralogical
phases and porosity from previous steps.
[0064] Sub-step 1: The elastic properties of the drilling cuttings
can be estimated by directly doing ultrasonic measurements of the
P- and S-wave velocities using two known techniques such as the
pulse transmission technique [Santarelli, F. J. et al.: Formation
Evaluation From Logging on Cuttings, SPE Reservoir Evaluation &
Engineering, June 1998, SPE 36851, 238-244] and continuous wave
technique called CWT [Nes, O. M. et al.: Rig-Site and Laboratory
Use of CWT Acoustic Velocity Measurements on Cuttings, SPE
Reservoir Evaluation & Engineering, June 1998, SPE 50982]. Both
of these references are incorporated by reference herein. Systems,
such as CWT, are portable, fast and easy to use, and relatively
inexpensive, and are capable of measuring velocities also on
sub-mm-thick, finely grained samples like shale. This step can
provide two velocities measurements that can be translated into two
elastic moduli (Young modulus and poisson's ratio) but is unlikely
to provide any information on elastic anisotropy because the mixing
and rotation of the cutting samples means the original orientation
of the cuttings with respect to the formation is lost.
[0065] Sub-set 2: Another ways to estimate the elastic properties,
but including the anisotropy, is as follows: using the knowledge of
the fraction of the different mineralogical phases (organic and
inorganic) from steps 111-121-132 as well as the porosity and bulk
density from steps 111-121-134, using known elastic properties of
basic minerals and a rock physics model for shales taking into
account the different scale involved in shales, one can compute the
elastic moduli, E and, of effective elastic or poroelastic rocks.
Examples of such models are shown for example by Colin M. Sayers,
The effect of low aspect ratio pores on the seismic anisotropy of
shales, SEG, Expanded Abstracts, 27, 2750(2008), Joel Sarout and
Yves Gueguen, Anisotropy of elastic wave velocities in deformed
shales: Part 1-Experimental results, Geophysics, 73, D75, (2008),
Joel Sarout and Yves Gueguen, Anisotropy of elastic wave velocities
in deformed shales: Part 2--Modeling results, Geophysics, 73, D91,
(2008), and J. Alberto Ortega, Microporomechanical modeling of
shale, PhD, MIT, 2010, and J. Alberto Ortega, Franz-Josef Ulm, and
Younane Abousleiman, The nanogranular acoustic signature of shale,
Geophysics, 74, D65, (2009). These four references are incorporated
by reference herein. This technique provides an estimation of
anisotropic elastic properties, E.sub.h, E.sub.v, v.sub.h, v.sub.v,
and G.sub.v, along the well.
[0066] FIG. 7 is a flow chart to illustrate one embodiment of step
135. Acoustic and bulk density measurements may be combined with a
rock physics model (which may also encompass results from step 132)
to form an elastic property log.
Box 136: Analysis for Intrinsic Specific Energy and Rock
Strength
[0067] This step combines two sub-steps: (1) one being the signal
processing of the previously acquired data to isolate depth
intervals where the drilling mechanics response is homogeneous for
example using a Bayesian change-point methodology described by
patent application WO 2010/043851 A2 which is incorporated by
reference herein, and (2) another one using a mechanical model
relating weight-on-bit, torque-on-bit depth of cut per revolution
to intrinsic specific energy via a relationship between specific
energy and drilling strength, then relating the intrinsic specific
energy to compressive rock strength UCS as described by U.S. Pat.
No. 5,216,917 A and PCT Patent Number WO 2010/043851 A2 which is
incorporated by reference herein.
[0068] One can, for example, use the mechanical model described by
Detournay, E. and P. Defourny (1992), A phenomenological model of
the drilling action of drag bits, Int. J. Rock Mech. Min. Sci.,
29(1):13-23 and Emmanuel Detournay, Thomas Richard, Mike Shepherd,
Drilling response of drag bits: Theory and experiment,
International Journal of Rock Mechanics and Mining Sciences, Volume
45, Issue 8, 2008, 1347-1360 to describe the relationship between
drilling data and rock strength using a rate-independent interface
law, as follows. These two references are incorporated by reference
herein. [0069] Three basic state variables are defined as a scaled
weight-on-bit w=W/a, scaled torque-on-bit t=2T/(a*a) and the depth
of cut per revolution d=2.pi.r*V/.OMEGA. where W(=WOB) is the
weight-on-bit, T(=TOB) the torque-on-bit, V(=ROP) the rate of
penetration, .OMEGA.(=RPM) the angular velocity and a is the bit
radius. [0070] The specific energy E is defined as E=t/d, and the
drilling strength S as S=w/d. [0071] The linear relationship
between E and S that is E=(1-.beta.).epsilon.+.mu..gamma.S (where c
is the intrinsic specific energy, .mu. is the coefficient of
friction at the wear flat-rock interface and .gamma. a bit
constant) can be used to estimate the intrinsic specific energy c.
[0072] Empirical linear relationship between intrinsic specific
energy c and the compressive rock strength UCS can then be used.
Using the previous model for each depth interval where the drilling
mechanics response is homogeneous, one can obtain a log of
intrinsic specific energy and UCS. For example, FIG. 8 is a flow
chart of one embodiment of step 136. Processing the SWOD, STOR,
ROP, and RPM from surface and downhole sensors can be used to form
a log of intrinsic specific energy and UCS.
Box 137: Analysis for Closure Stress
[0073] The analysis of the pressure and volume as a function of
time for closure is done classically on microfracturing data where
the formation breakdown pressure can identified and where the
pressure decline after the injection as stopped leads to the
identification of the ISIP (Instantaneous shut-in pressure)
pressure and the closure stress pressure. Several graphical
representation of the data are possible for the analysis (known as
Homer plot, G-function, etc, See book from Economides and Nolte,
Reservoir stimulation, 2000, Wiley, 3rd edition). When multiple
cycle are conducted and the pressure decrease is recorded for a
sufficiently long time, it has been shown that accurate can be
obtained. We refer to following papers for the interpretation:
Adrian J. White, Martin O. Traugott, and Richard E. Swarbrick "The
use of leak-off tests as means of predicting minimum in-situ
stress" Petroleum Geoscience, Vol. 8 2002, pp. 189-193; A. M.
Raaen, P. Horsrud, H. Kjorholt, D. Okland 2003 "Improved routine
estimation of the minimum horizontal stress component from extended
leak-off tests." International Journal of Rock Mechanics &
Mining Sciences 43 (2006), pp. 37-48. These three papers are
incorporated by reference herein.
[0074] This step leads to the estimation of point-wise closure
stress measurements where the tests are performed. For example,
FIG. 9 is a flow chart of one embodiment of step 137. The hydraulic
test is interpreted, then closure stress is measured along the
well. This is combined for completion quality data step 142.
Reservoir Quality and Completion Quality
Box 141: Reservoir Quality (RQ) Data
[0075] This step 141 includes both the graphical display of all
data collected in steps 131-132-133-134 as function of the depth of
the well and the computation and display of the "Reservoir Quality
(RQ)" index. Data from steps 131-132-133-134 include volume, type
and isotope distribution of gas, weight or volume fraction of
inorganic minerals and organic kerogen (with or without maturity),
pore volume, surface area, porosity and gamma (LWD GR and measured
on cuttings). One way to compute the RQ index would be to create
either a piece-wise constant property log using a blocking
algorithm where cut-off conditions are defined for each properties
or a composite log using a weighted score algorithm from the
multiple input logs. The output of such computation is binary
"good/bad" RQ index.
Box 142: Completion Quality (CQ) Data
[0076] This step 142 includes both the graphical display of all
data collected in steps 135-136-137 as function of the depth of the
well and the computation of "Completion Quality (CQ)" index. Data
from steps 135-136-137 include the 2 to 5 elastic moduli, rock
strength, and closure stress. Based on the elasticity data and
closure data, a closure stress index can be computed [M. J.
Thiercelin, SPE, and R. A. Plumb, 1994, A Core-Based Prediction of
Lithologic Stress Contrasts in East Texas Formations, SPE Formation
Evaluation, Volume 9, Number 4, Society of Petroleum Engineers
21847; George A. Waters, Richard E. Lewis and Doug C. Bentley,
2011, The Effect of Mechanical Properties Anisotropy in the
Generation of Hydraulic Fractures in Organic Shales, SPE Annual
Technical Conference and Exhibition, 30 October-2 Nov. 2011,
Denver, Colo., USA, Society of Petroleum Engineers 146776.]. One
way to compute the CQ index would be to create either a piece-wise
constant property log using a blocking algorithm where cut-off
conditions are defined for each properties or a composite log using
a weighted score algorithm from the multiple input logs. The output
of such computation is binary "good/bad" CQ index.
Box 151: Selective Staging of Hydraulic Fractures from RQ and CQ
Index
[0077] This step includes both the graphical display of all
information from steps 141-142 and an algorithm that optimizes the
number and position of fracturing stages and the number and
position of perforation clusters from a stage based on RQ and CQ
indexes.
[0078] Examples of such algorithms covering steps 141, 142 and 151
are given m C. Cipolla, X. Weng, H. Onda, T. Nadaraja, U. Ganguly,
and R. Malpani, 2011, New Algorithms and Integrated Workflow for
Tight Gas and Shale Completions, SPE Annual Technical Conference
and Exhibition, 30 October-2 Nov. 2011, Denver, Colo., USA, Society
of Petroleum Engineers 146872 and U.S. patent application Ser. Nos.
13/338,732 and 13/338,784. These paper and patent applications are
incorporated by reference herein.
[0079] Generally, characterizing the reservoir quality may include
using information from a mud gas log, DRIFTS, gas sorption, XRD,
XRF, natural spectral GR, NMR, drilling data, calcimetry, Raman
spectroscopy, NMR Spectroscopy, cross-polarization magic angle
spinning NMR, loss on ignition, hydrogen peroxide digestion,
petrography, thermal alteration index, elemental analysis, wet
oxidation followed by titration with ferros ammonium sulfate or
photometric determination of Cr3+, wet oxidation followed by the
collection and measurement of evolved CO2, dry combustion at high
temperatures in a furnace with the collection and detection of
evolved CO2 or a combination thereof. Additional patent
applications that provide additional processes, procedures, and
details for the analysis of cuttings and other relevant process
steps include United States Provisional Patent Application Ser.
Nos. 61/623,636, 61/623,646, and 61/623,694, filed on Apr. 13,
2012, all three of which are incorporated by reference herein.
[0080] U.S. patent application Ser. No. 13/446,995, filed Apr. 13,
2012, which is incorporated by reference herein includes additional
details, processes and procedures that related to the processes
described herein. A detailed analysis of TOC characterization may
be obtained from "Methods for the Determination of Total Organic
Carbon (TOC) in Soils and sediments by Brian A. Schumacher of the
United States Environmental Protection Agency Ecological Risk
Assessment Support Center NCEA-C-1282, EMASC-001, April 2002, which
is incorporated by reference herein.
Additional Advantages
[0081] Embodiments of the invention may benefit from near real time
geosteering, a characterization guide completion job with a short
time requirement, and characterization that happens over time that
may be used for reservoir modeling, such as clay identification,
refracturing planning, and well remediation for casing issues. One
embodiment enables the assessment of reservoir and completion
quality of an unconventional shale gas reservoir, by integrating
information from a mud-gas log, drill-bit cuttings and drilling
data. The basic driver is to create a practical and efficient
solution to obtain the needed data to design a completion job
(hydraulic fracturing), in the absence of wireline or LWD well logs
and/or core data. The data from old wells can also be used later
for better reservoir modeling and management. Data from these three
components can be integrated, without any logs or core data, to
assess reservoir and completion quality.
[0082] One embodiment proposes a solution that satisfies all the
above criteria, by combining a mud-gas log, organic and inorganic
formation properties obtained from cuttings, and geomechanical data
derived from drilling data to help design a completion program that
optimizes the resources available and potential production. The
data is collected over discrete intervals, depending on drilling
speed and available resources, typically in 30 to 90 foot
windows.
[0083] While the intended target for some embodiments is horizontal
wells, vertical wells may also benefit from techniques described
above. Furthermore, the data acquired previously can later be
analyzed in post-mortem mode, to investigate production anomalies
or other inconsistencies, among wells already drilled and are
producing.
[0084] The oil field service may be selected from the group
consisting of drilling hydraulic fracturing, geosteering,
perforation and a combination thereof.
[0085] Time and location are important considerations for
embodiments of this procedure. The analyzing occurs in less than an
hour and/or in less than 24 hours in some embodiments. The
analyzing occurs before recovering hydrocarbons begins in some
embodiments or after producing hydrocarbons begins in some
embodiments. The analyzing may occur during reservoir
characterization during production. Some embodiments may use
equipment within 500 meters of a wellbore. In some embodiments,
analyzing occurs while drilling the formation.
* * * * *